Category: Nieuws

Energy Transfer LP (NYSE: ET) (“Energy Transfer”) and Crestwood Equity Partners LP (NYSE: CEQP) (“Crestwood”) announced today that the parties have entered into a definitive merger agreement pursuant to which Energy Transfer will acquire Crestwood in an all-equity transaction valued at approximately $7.1 billion, including the assumption of $3.3 billion of debt, based on the closing price on August 15, 2023.

Under the terms of the agreement, Crestwood common unitholders will receive 2.07 Energy Transfer common units for each Crestwood common unit. The transaction is expected to close in the fourth quarter of 2023, subject to the approval of Crestwood’s unitholders, regulatory approvals, and other customary closing conditions. Upon closing, Crestwood common unitholders are expected to own approximately 6.5% of Energy Transfer’s outstanding common units.

Complementary Assets

Crestwood’s system includes gathering and processing assets located in the Williston, Delaware and Powder River basins, including approximately 2.0 billion cubic feet per day of gas gathering capacity, 1.4 billion cubic feet per day of gas processing capacity and 340 thousand barrels per day of crude gathering capacity. If consummated, this transaction would extend Energy Transfer’s position in the value chain deeper into the Williston and Delaware basins while also providing entry into the Powder River basin. These assets are expected to complement Energy Transfer’s downstream fractionation capacity at Mont Belvieu, as well as its hydrocarbon export capabilities from both its Nederland Terminal in Texas and the Marcus Hook Terminal in Philadelphia, Pennsylvania.

This transaction is also expected to provide benefits to Energy Transfer’s NGL & Refined Products and Crude Oil businesses with the addition of strategically located storage and terminal assets, including approximately 10 million barrels of storage capacity, as well as trucking and rail terminals. These systems are anchored by predominantly investment-grade producer customers with firm, long-term contracts, and significant acreage dedications.

Positive Financial Impact

The transaction is expected to be immediately accretive to distributable cash flow per unit as well as neutral to Energy Transfer’s leverage metrics upon closing. Similar to Energy Transfer, Crestwood’s cash flows are supported by primarily fee-based revenues from long-term contracts with investment-grade counterparties. In addition, with the increased scale and strengthened balance sheet, Energy Transfer expects to be able to improve on the current cost of financing for the acquired debt securities. Structured as a 100% unit-for-unit exchange, the transaction is tax-efficient to Crestwood unitholders and is anticipated to position both partnerships for long-term value upside through the combination.

Energy Transfer also expects to achieve at least $40 million of annual run-rate cost synergies before additional benefits of financial and commercial opportunities.

Compelling Value Creation for Crestwood Unitholders

Energy Transfer’s premier business model, strong balance sheet and backlog of growth opportunities supports the potential for significant additional value creation over time. The tax-efficient transaction is expected to provide Crestwood unitholders a benefit to distributions per unit and an opportunity to participate in Energy Transfer’s targeted annual distribution per unit growth rate of 3-5%.

Advisors

BofA Securities acted as sole financial advisor to Energy Transfer and Kirkland & Ellis LLP acted as legal counsel. Intrepid Partners, LLC and Evercore acted as financial advisors to Crestwood and Vinson & Elkins LLP acted as legal counsel.

Crestwood Investor Call

Crestwood management will host a conference call for investors and analysts of Crestwood today at 9:00 a.m. Eastern Time (8:00 a.m. Central Time), which will be broadcast live over the Internet. Investors will be able to access the webcast via the “Investors” page of Crestwood’s website. Please log in at least ten minutes in advance to register and download any necessary software. A replay will be available shortly after the call for 90 days.

By Energy Transfer, August 23, 2023

Enbridge Inc. (NYSE: ENB) and (TSE: ENB) has received an average rating of “Moderate Buy” by six brokerages covering the stock, according to a report by Bloomberg. Out of the six investment analysts, three have assigned a hold rating while the remaining three have given a buy rating to the company. The average 12-month target price based on analysis from various brokerages is $57.67.

On Friday, August 14, 2023, NYSE ENB opened at $36.72. Over the past fifty days, the business has maintained a moving average price of $36.90 and over the last 200 days, it recorded an average moving price of $38.01. Enbridge’s one-year low stands at $35.02 with its highest point reaching $44.55 during the same period.

Notably, Enbridge holds a debt-to-equity ratio of 1.27, indicating its utilization of borrowed funds in relation to equity investments. The company boasts a quick ratio of 0.51 and current ratio of 0.64, suggesting its ability to meet short-term obligations using assets that can be readily converted into cash. With a market capitalization of $74.27 billion, Enbridge operates with a price-to-earnings ratio of 26.23 and a beta value of 0.84.

Enbridge Inc., along with its subsidiaries, serves as an energy infrastructure company that operates through five main segments: Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution and Storage, Renewable Power Generation, and Energy Services.

The Liquids Pipelines segment primarily focuses on operating pipelines and associated terminals for transporting diverse grades of crude oil as well as other liquid hydrocarbons across Canada and the United States.

As an energy infrastructure leader in North America, Enbridge aims to ensure reliable access to energy resources for customers while considering the environmental impact. The company demonstrates its commitment to sustainability and renewable energy through its Renewable Power Generation segment, which complements its traditional energy operations.

Enbridge’s Gas Transmission and Midstream segment focuses on transporting natural gas, enabling it to meet the growing demand for this cleaner fuel source. The company’s Gas Distribution and Storage segment manages regulated natural gas distribution systems in Canada and contributes to improving environmental standards within the industry.

Furthermore, Enbridge offers Energy Services, expanding its portfolio to include a range of energy-related activities such as marketing, supply and logistics services.

In conclusion, Enbridge Inc. emerges as an important player in the energy infrastructure sector. With an average “Moderate Buy” rating from brokerages and a target price of $57.67 according to analyst predictions, the company presents potential investment opportunities. As it continues to navigate the complexities of the energy industry, Enbridge’s strategic segments allow it to adapt to changing market demands while promoting sustainable practices in line with environmental considerations.

By Best Stocks, August, 2023

Three numbers encapsulate the story of Saudi Aramco since its initial public offering (IPO) in December 2019. The first is that its net income for the second quarter (Q2) of this year was US$30.1 billion. The second is that its regular quarterly dividend was US$19.5 billion. And the third is that on top of this regular dividend, it will also start paying an additional promised performance-linked dividend of US$9.9 billion in the next quarter.

So, even with a Brent oil price averaging around US$80 per barrel (pb) in Q2 – an historically elevated price for ‘non-crisis’ oil markets in recent years – 65 percent of its net income went on a debt to shareholders, in the form of dividends.

If the net income stayed the same in Q3, this debt payment would rise to 98 percent. The story is, then, that due to the ill-conceived IPO thought up in late 2015/early 2016 by Crown Prince Mohammed bin Salman (MbS), Saudi Arabia’s corporate crown jewel must continue to operate under a crushing debt burden.

Because of that, it is limited in the new exploration and development work it can do, which cripples its ability to increase its reserves and its production numbers. Because of that, it will keep having to act as the instrument through which Saudi Arabia continues to push oil (and gas) prices higher. And because of that, the U.S. at some point will fully enact the ‘No Oil Producing and Exporting Cartels’ (NOPEC) bill and destroy Saudi Aramco as we know it today. 

It should be remembered that back in late 2015/early 2016, MbS conceived the plan to IPO Aramco as a key part of his strategy to take over the position of heir-designate to King Salman from Prince Muhammad bin Nayef (MbN). In theory, the idea had several positive factors going for it that would benefit MbS. First, it could raise a lot of money, part of which might be used to offset the economically disastrous effect on Saudi Arabia of the 2014-2016 Oil Price War, as analysed in my new book on the new global oil market order.

Second, it could boost Saudi Arabia’s reputation in the global financial markets, which would help with further IPOs and would boost foreign investment into the country’s domestic capital markets more broadly. And third, both new funding flows could be used as part of the ‘National Transformation Program’ 2020 – in turn part of Saudi’s ‘Vision 2030’ development plan – that sought to diversify the Kingdom’s economy away from its reliance on oil and gas exports. After a few months of further discussion, MbS assured senior Saudis that he could absolutely ensure the flotation of 5 percent of Aramco, which he said would absolutely raise at least US$100 billion in much-needed funds for Saudi Arabia.

This, in turn, would place a valuation on the entire company of at least US$2 trillion. In addition, MbS said, Saudi Aramco would absolutely be listed on one of the world’s major stock exchanges, with the New York Stock Exchange and the London Stock Exchange being the two preferred options.

This theory ran into practical difficulties from the moment that major Western investors began to look at Aramco in more depth. For a start, the crude oil production figures that Saudi Arabia had long bandied around as being fact were evidently no such thing, as forensically analysed in my new book.

Far from being able to produce 10, 11 or 12 or more million barrels per day (bpd), Saudi Arabia struggled to produce anything over 9 million bpd. To be accurate: from 1 January 1973 to Monday 14 August 2023, Saudi Arabia’s average crude oil production is 8.257 million bpd. This means that its equally much-vaunted spare capacity of around 2 million bpd is also not true, founded as it is on a false baseline crude oil production capability.

Additionally concerning then, as now, were Saudi Arabia’s equally fantastical claims about its oil reserves. Specifically, at the beginning of 1989, the country claimed proven oil reserves of 170 billion barrels. Just one year later, and without the discovery of any major new oil fields, it claimed proven oil reserves of 257 billion barrels, an increase of 51.2 percent. Shortly afterwards, Saudi Arabia’s proven oil reserves miraculously increased again, this time to just over 266 billion barrels, again without the discovery of any major new oil fields. Proven oil reserves increased once more in 2017, to 268.5 billion barrels, again with no new major oil finds being discovered.

At the same time as these increases being announced, the country was extracting an average of 8.162 million bpd. Therefore, from 1990 (the year in which Saudi Arabia’s claimed proven oil reserves jumped from 170 billion barrels to 257 billion barrels), to 2017 (the year when Saudi Arabia was claiming proven oil reserves of 268.5 billion barrels), Saudi Arabia had physically removed from the ground forever an average of just over 2.979 billion barrels of crude oil every year.

The total amount of crude oil permanently removed from the beginning of 1990 to the beginning of 2017, was, then, 80.43 billion barrels. In short, from 1990 to 2017, Saudi Arabia’s official crude oil reserves number had gone up 98.5 billion barrels, despite there being no new oil finds and it physically removing 80.43 barrels forever. 

These facts – together with Aramco being used as a key source of funding for various socio-economic projects that had nothing to do with its business and would destroy shareholder value – meant that no major global financial players wanted to invest in Aramco and not a single major Western or Eastern stock market wanted Aramco to list on it.

Given this, the stage was set for a series of events that help to define the new global oil market order, as also analysed in depth in my new book on that subject. One of these was a face-saving offer for MbS from China that he has never forgotten and that has underpinned Saudi Arabia’s drift towards China since then. Another was the expediting of Saudi Arabia’s move away from the U.S. and towards Russia that had been gathering pace since the end of the Second Oil Price War in 2016.

Even more specifically for Saudi Aramco, it meant that MbS had to offer massive incentives to investors to buy any of the IPO. One of these was a guarantee by the Saudi government that, whatever happened, it would pay a US$75 billion dividend payment in 2020, split equally into payments of US$18.75 billion every quarter. These payments, of course, have now risen and will be made even more destructive to Aramco’s basic functioning by the addition of extra performance-linked dividends.

These are designed to target 50-70 percent of annual free cash flow, net of the base dividend, and other amounts including external investments, according to Aramco’s chief executive officer, Amin Nasser.

The highly precarious financial tightrope on which Aramco finds itself also means that Saudi Arabia has no alternative but to keep pushing oil (and gas) prices ever higher. And, as day follows night, this means a collision course with the U.S. and its allies, who regard rising energy prices as direct threats to their economic and political well-being. This comes on top of an increasingly antagonistic relationship between the U.S. and Saudi Arabia, following the de facto break-up of their foundation stone 1945 agreement.

The mechanism to destroy Aramco in its current form is already in place, in the form of the NOPEC bill, as also analysed in my new book. This legislation would open the way for sovereign governments to be sued for predatory pricing and any failure to comply with the U.S.’s antitrust laws. OPEC is a de facto cartel, Saudi Arabia is its de facto leader, and Saudi Aramco is Saudi Arabia’s key oil company.

The enactment of NOPEC would mean that trading in all Saudi Aramco’s products – including oil – would be subject to the antitrust legislation, meaning the prohibition of sales in U.S. dollars. It would also mean the eventual break-up of Aramco into smaller constituent companies that are not capable of influencing the oil price.

OilPrice.com by Simon Watkins, August 23, 2023

Asian refiners are on the hunt for crude oil to replace Kuwaiti supply as the OPEC producer cuts exports by nearly a fifth to feed its huge new refinery, which is driving up prices for other sour crudes and likely to squeeze profit margins.

Lower Kuwaiti exports follow cuts from OPEC kingpin Saudi Arabia that have pushed Brent prices close to $90 a barrel and left little wriggle room for Asia’s refiners, reliant on the Middle East for more than two-thirds of crude imports.

Chinese refiners, which have invested heavily in new plants designed to process sour oil, are especially exposed.

Discounted oil from Russia has eased some of the pain, replacing some Kuwaiti supply, largely to China and India.

But most of Kuwait’s customers will have to pay up for similar quality oil from other suppliers such as Saudi Arabia, Iraq and the United Arab Emirates or buy more expensive sweet grades from other regions.

“Saudi Arabia and the UAE are the top contenders for filling the supply gap in the Middle East due to their production and export of medium sour barrels,” said Janiv Shah, an analyst at consultancy Rystad Energy.

“It is improbable that they will be able to entirely meet the demand.”

Sustained output cuts from OPEC producers and their allies and new refining capacity designed to process sour crude could lead to tight supply until the end of 2024, Energy Aspects analyst Sun Jianan said.

Kuwait’s crude shipments shrank by about 10% to 1.61 million barrels per day (bpd) in January-July from the same period in 2022 as its Al Zour refinery ramped up, according to Kpler data.

Exports to Taiwan, China and India dropped more than 17% during the same period, while volumes for Pakistan, the Philippines and Thailand fell to zero, the data showed.

In the second half, Kuwait will reduce its exports by up to 300,000 bpd, down 18% from the first half, as it diverts supply to the 615,000 bpd Al Zour plant, which cranked up its third and final crude distillation unit (CDU) in July, according to consultancies FGE, Energy Aspects, Rystad Energy and S&P Global Commodity Insights.

Additionally, Kuwait’s joint venture 230,000 bpd Duqm refinery in Oman is scheduled to start operation by end-2023, which could reduce Kuwaiti crude exports by a further 100,000 bpd to 200,000 bpd in 2024, the consultancies said.

Kuwait Petroleum Corp (KPC) has notified buyers that volumes could fluctuate each month and could be further reduced once Al Zour is at full operation, a source familiar with the matter said.

KPC did not respond to Reuters’ inquiry seeking comment.

THIRSTY REFINERS

The supply squeeze comes as over 1 million barrels per day (bpd) of new Chinese refining capacity comes online. The 320,000-bpd Shenghong refinery and PetroChina’s (601857.SS) 400,000-bpd Guangdong plant started commercial operations earlier this year, while Yulong Petrochemical’s 400,000-bpd refinery is scheduled to start trial runs in the fourth quarter.

“Almost all refineries in China are designed to process mainly medium sour crude oil,” said a Chinese oil trader, adding that tight supply would depress margins at Chinese refineries already struggling with tepid product demand.

Exports to key buyers – China, Japan, South Korea, India and Taiwan – are expected to drop further from October once Kuwait resumes supply to its Vietnam joint venture Nghi Son refinery following two months of scheduled maintenance work.

“The supply reduction in 2023 was factored in our term contract discussed last year,” KY Lin, spokesperson at Taiwan Formosa Petrochemical Corp (6505.TW) said, adding that negotiations for 2024 supply will commence soon.

Formosa could replace Kuwaiti supply with grades such as Iraq’s Basra Medium, Qatar’s al-Shaheen and Oman crude, Lin said, adding it can also process U.S. light sweet crude.

PRICES CLIMB

Middle East crude exports are expected to slump by nearly 8%, or up to 1.35 million bpd, in the second half of 2023 from the first half, said James Forbes, an analyst at FGE.

Refiners are already feeling the pinch as Middle East producers have hiked official selling prices (OSPs) for July to September supplies.

In signs supply is tightening, in August, benchmark Dubai’s first month was trading $2.11 a barrel higher than the third month, compared with a difference of $1.14 in June.

And the discount for sour Dubai crude against sweet Brent crude has narrowed sharply to around $1 a barrel from nearly $6 at the start of the year and briefly even fetched a small premium to Brent in June.

“The Brent-Dubai spread has recently widened but we do see some potential to narrow again if Asian demand strengthens further,” said Shah.

Reuters by Muyu Xu, August 23, 2023

Africa’s secret weapon in the global energy race – green hydrogen. The continent has the potential to flip the script, transitioning from a fossil fuel consumer to a green energy titan.

The global energy transition has a burgeoning champion – green hydrogen. Often overshadowed by solar and wind, this renewable resource is increasingly crucial for a sustainable future.

The current global hydrogen market is over $130 billion. The World Bank predicts an annual growth of over 9%. Although the surge is likely niche until 2030, the growing demand for renewable energy means that green hydrogen could accelerate rapidly thereafter. Regions with low-cost markets and abundant renewable resources, like Africa, become attractive production markets.

The principle is straightforward. Use renewable energy sources to split water into hydrogen and oxygen. The result? A fuel source that releases only water upon consumption. The applications are limitless, from powering cars to heating homes.

What is green hydrogen?

At its core, green hydrogen is simple. It’s hydrogen, the universe’s most abundant element, produced environmentally friendly. But how do we make it, and why does it matter?

Green hydrogen is generated via electrolysis, which splits water into hydrogen and oxygen using electricity. But for the hydrogen to be ‘green’, the electricity must come from renewable sources, like wind or solar power. The only byproduct is oxygen, a harmless gas we breathe every day.

In contrast, most hydrogen produced today is ‘grey’ or ‘blue’. It’s derived from fossil fuels, mainly natural gas, and the process releases significant amounts of carbon dioxide, a harmful greenhouse gas. Green hydrogen represents a shift away from this environmentally damaging status quo. However, green hydrogen faces challenges. Currently, it accounts for less than 1% of all hydrogen production. The main obstacle is the production cost, which is not yet competitive compared to grey or blue hydrogen. Most green hydrogen is used in energy-intensive industries like steel and chemical manufacturing.

The path to economic viability for green hydrogen lies in a combination of technological advancements, increased global development investment, and legislative commitments. These factors are expected to make green hydrogen a serious market contender in the coming decades.

Africa is fast becoming a frontrunner in the green hydrogen race.

“FROM SOLAR TO BIOGAS, FROM WIND TO BATTERY STORAGE, THESE INVESTMENTS ARE LEADING ONE OF THE MOST IMPORTANT GROWTH INDUSTRIES IN OUR COUNTRY.”—South African President Cyril Ramaphosa

Blessed with an abundance of sunlight and wind, Africa is ideally positioned to exploit green hydrogen’s potential. Groundbreaking projects are taking shape across the continent.

From the ambitious SA-H2 venture announced recently in South Africa to a green hydrogen initiative between Namibia and Botswana, these projects signal profound economic opportunities for job creation, growth, and sustainable development.

The Africa Green Hydrogen Alliance (AGHA), established in 2022, emphasizes Africa’s competitive edge due to low production costs. Masopha Moshoeshoe, Green Economy Specialist at the Investment and Infrastructure Office in the Presidency of South Africa, stated in a press release issued by the United Nations Framework Convention on Climate Change on the launch of the alliance: “Green hydrogen has the potential to marry South Africa’s significant mineral endowment with its significant renewable revolutionize its energy sector. The SA-H2 fund, which aims to establish a hydrogen ecosystem in South Africa, is at the forefront of this exciting transition.

The $1-billion fund was announced in June as part of a joint effort between the Netherlands, Denmark and South Africa.

“From solar to biogas, from wind to battery storage, these investments are leading one of the most important growth industries in our country,” said South African President Cyril Ramaphosa at the announcement in Pretoria.

Blended finance is a key concept underpinning this project.

Andrew Johnstone, the CEO of Climate Fund Managers, explains to FORBES AFRICA that it refers to the strategic use of public

or philanthropic funds to mobilize private sector investment in sustainable development. In the context of SA-H2, this means bringing together private and public funding to make projects economically viable.

“They (the funds) act as a “spark” to ignite and mobilize belief, technology, and other forms of capital,” says Johnstone.

“The SA-H2 project should be seen as part of a larger effort across the region to leverage blended finance for sustainable energy development.”

The project is financed by a combination of different forms of capital, each with a different return requirement. This includes donor capital, commercial capital, and guarantees. By bringing these diverse sources of funding together, the project achieves a lower average cost of capital.

Johnstone explains, “Blended finance means in this context… to bring in capital in defined proportions in pursuit of a low average cost of capital.” Notably, this blended finance model also allows

for differential risk sharing. If a project underperforms, certain investors may not receive a return, thus sharing the risk in a structured and agreed-upon manner.

Once a project is up and running, it has an obligation to repay its funders, whether those are lenders through equity or energy loans, or others through dividends. Johnstone describes this repayment as a “waterfall”, with those who took the least risk and accepted a lower return being repaid first.

It’s important to highlight the transparency and regulation of these funds. They operate similarly to companies, are regulated by appropriate bodies, and are overseen by advisory boards and investment committees populated by investors or independent representatives. This governance structure ensures a high level of oversight and accountability.

Another key aspect of the SA-H2 project is the co-existence of different funds. The development side of the project is planned with public contracts and equity funds in mind. This co-existence helps redefine what “bankable” means in the context of these projects, potentially accelerating the implementation process.

These blended finance projects aim to create scalable, replicable, and improvable markets, serving as a catalyst for broader change in the energy sector.

South Africa’s SA-H2 initiative is not alone in its ambition.

Namibia is also making significant strides in the green hydrogen sector.

Noteworthy is a project in the Tsau Khaeb National Park, near Lüderitz, with the Namibian government proactively confirming a 24% equity stake in this $10 billion project, almost equivalent to the country’s gross domestic product.

This initiative, led by Hyphen Hydrogen Energy, is gaining momentum with several key partners signing a Memorandum of Understanding to collaborate on the necessary infrastructure for Namibia’s green hydrogen production ambitions.

“Namibia is perfectly positioned to produce low-cost green hydrogen and ammonia for domestic and international markets,” said Frans Kalenga, Technical Advisor to the Minister of Mines and Energy of Namibia on Namibia’s joining of the AGHA, in a press statement. “[It] provides a platform for us to collaborate with neighboring countries. AGHA’s report reaffirms the potential, and provides important recommendations on how we can work together to unlock the extraordinary potential.”

This potential is estimated to generate 15,000 jobs during the direct construction of the project, and a further 3,000 created permanently when the project is fully underway.

Namibia’s Vice President Nangolo Mbumba acknowledged the global transition toward green hydrogen, as well as the country’s abundant natural resources and landscape assisting in the suitability of its development as an industry.

“We are now approaching new fields of economy. Everybody is talking about green hydrogen. Three-four years ago, even the pronunciation was not known,” he said, speaking during the Forbes Under 30 Summit Africa in Botswana in April. “People need energy, and plenty of it,” he continued, acknowledging the international collaboration, local training and investment in education to develop the skills needed for green hydrogen initiatives.

“If we succeed, we will produce enough energy for the whole region of southern Africa,” added Mbumba.

Policy and profitability

A confluence of factors is propelling the growth of green hydrogen in Africa. The continent’s abundant natural resources, particularly sunlight and wind, provide an ideal setting for green hydrogen production. Escalating global demand for clean energy is creating opportunities for African nations to emerge as green hydrogen exporters. Moreover, policymakers are increasingly recognizing green hydrogen’s potential in achieving climate goals and fostering sustainable development.

The advent of green hydrogen presents a substantial opportunity for job creation across the African continent.

With Africa positioned as a potential global exporter of green hydrogen, the sector could become a significant contributor to the continent’s GDP. Moreover, the revenues generated from green hydrogen exports could be reinvested into local communities, improving infrastructure, education, and healthcare.

An analysis by McKinsey on behalf of AGHA identified a possible increase in GDP for member countries of between $66 billion and $126 billion by 2050, as well as up to 4.2 million new jobs as a result of green hydrogen investments.

The potential offers a pathway for nations to build a more resilient future, mitigating economic risks tied to unpredictable oil and gas prices. By developing a green hydrogen industry, nations could foster local technological innovation and enhance their manufacturing capabilities.

This prospect could shift Africa’s role in the global energy landscape, transitioning from a net importer of fossil fuels to a significant exporter of clean energy.

However, the promise of green hydrogen is not solely economic. It also offers a sustainable solution that addresses the pressing issues of economic development and climate change simultaneously.

Green Hydrogen is a tool for survival

As the world stands on the brink of a pivotal moment in its fight against climate change, green hydrogen emerges as a powerful ally. As a clean, carbon-free source of energy, green hydrogen can replace fossil fuels in various sectors, leading to a dramatic reduction in greenhouse gas emissions.

In Africa, where climate change threatens both people and ecosystems, investing in green hydrogen will not only enable nations to contribute to global emission reductions but also helps them build resilience against climate change impacts at home.

Even though Africa is responsible for only a fraction of global carbon emissions, the continent is actively taking steps to reduce its carbon footprint.

Green hydrogen can play a significant role in these efforts, replacing carbon-intensive fuels across the economy and leading to substantial emission reductions.

Moreover, exporting green hydrogen to other continents could further reduce global carbon emissions, enhancing Africa’s contribution to the global fight against climate change.

Renewable energy has been identified by many African countries as a key element of their climate change mitigation strategies. Incorporating green hydrogen into these strategies could hasten their progress towards achieving climate goals.

By offering a means to store and transport renewable energy, green hydrogen could solve one of the significant challenges of the energy transition: the intermittency of wind and solar power. This could facilitate a more extensive and efficient use of renewable energy, driving further emission reductions.

At the heart of the global energy transition, green hydrogen stands out as a beacon of hope. This renewable resource, making waves in the energy sector worldwide, has found a promising home in Africa. The continent, blessed with abundant wind and sunlight, is quickly gaining recognition as a potential global leader in green hydrogen production.

Pioneering projects across the continent signify Africa’s commitment to embracing green hydrogen.

Yet, the narrative of green hydrogen extends beyond economics. It is a tale of resilience and innovation in the face of climate change. Looking ahead, it’s clear that green hydrogen could reshape Africa’s energy landscape, transforming the continent from a net importer of fossil fuels to a major exporter of clean energy. Such a transformation could not only stimulate economic growth but also enhance Africa’s influence in global energy and climate policy discussions.

For Africa, the opportunity is now. It’s an opportunity that calls for further research, investment, and policy support, for the sake of the continent and the world.

Africa Forbes by Yeshiel Panchia, August 23, 2023

When Switzerland joined sanctions against Moscow, a chunk of the world’s oil trade relocated to the Middle East. Some predict it will stay there.

For decades, the lakeside city of Geneva was home to many of the traders who sold Russia’s oil to consumers around the world. But since Switzerland joined the embargo imposed on Moscow following its invasion of Ukraine much of that trade has shifted to Dubai and other cities in the United Arab Emirates.

Companies registered in the small Gulf state bought at least 39 million tonnes of Russian oil worth more than $17 billion (CHF14.6 billion) between January and April – around a third of the country’s exports declared to customs during that period – according to Russian customs documentation analysed by the Financial Times.

Some of that oil ended up in the UAE, ship-tracking data shows, landing at storage terminals in places such as Fujairah. The rest – about 90% – never touched Emirati soil, instead flowing from Russian ports directly to new buyers in Asia, Africa and South America as part of one of the biggest redirections of global energy flows in history.

The energy trading industry in the UAE was already growing before Vladimir Putin’s invasion of Ukraine. But the conflict, and the western sanctions that followed it, have supercharged that growth.

Out of the top 20 traders of Russian crude in the first four months of the year, eight were registered in the UAE, the customs data shows. In refined petroleum products, such as diesel and fuel oil, UAE dominance was even higher, with ten of the 20 largest traders registered in the country.

The trading boom has further enriched the nation, moving billions of dollars of additional oil revenue through its banks and attracting dozens of new companies to its free-trade zones. It has also tested relations with allies such as the US, which wants Russian oil to flow but is wary of creating new trade routes that undermine sanctions.

Executives at trading houses say Dubai, the UAE’s main commercial centre, is a heady mix of excitement, competition and suspicion as new trading teams battle for talent and trade flow in a market suddenly rife with buyers and sellers.

“If you are an oil trader, this is where you want to be,” says Matt Stanley, a former trader and 20-year industry veteran who now manages client relationships in the region for data provider Kpler. “Dubai is the new Geneva.”

Political neutrality

The UAE, which juts from the Arabian peninsula into the Gulf of Oman, has been an important commercial hub for centuries, attracting merchants who shuttled goods between Europe and Asia. In recent years it has become a major trading location for gold, diamonds and agricultural commodities, such as tea and coffee, helped by its modern business infrastructure, banking services and light-touch regulation.

The UAE is the world’s eighth-largest oil producer, but historically has not been a major oil trading location. Volumes were modest and Adnoc, Abu Dhabi’s state oil company, only set up its own trading arm three years ago.

However, the country’s proximity to growing oil markets in Africa and Asia and the absence of personal income taxes had started to attract more profit-hungry traders even before the war in Ukraine.

“This is one of the last locations in the world to live and not pay tax,” says the chief financial officer of one trading house. Traders in his group’s other offices around the world are now regularly requesting moves to Dubai, he adds. “This will become the global commodity trading hub.”

Another attraction is the UAE’s perceived political neutrality in a world where rivalries between global powers mean Russia is unlikely to be the last country to face European or US sanctions on its exports.

“The UAE gives you that platform to transact, trade and travel freely,” says the chief executive of an energy trading company set up in Dubai in the past five years.

But for all the UAE’s success in building modern business infrastructure and capitalising on its geographical location, it is the war in Ukraine and the UAE’s willingness to welcome Russian businesses that are driving the current boom. “The Ukraine crisis put it on steroids,” the chief executive says.

Russian boom

The Dubai Multi Commodities Centre (DMCC), in the city’s gleaming Jumeirah Lake Towers district, is one of the UAE’s biggest and most successful free zones. A three-dimensional model in the lobby of the headquarters displays the district’s 87 gleaming residential and commercial towers across its two-square-kilometre site, home to 22,000 registered companies.

It is also, arguably, the new centre of the Russian oil trading universe. Out of the 104 buyers of Russian oil listed on Russian customs declarations between January and April, at least 25 were companies registered in the DMCC.

Litasco, a trading arm of Russia’s Lukoil, traded almost 16 million tonnes of Russian crude and refined fuels between January and April worth more than $7 billion, making it the biggest single buyer of Russian oil during the period, according to the customs data. Most of the trading was done by Litasco Middle East DMCC, the declarations show.

The company previously had only a representative office in the UAE, but some of its trading operations moved from Geneva to Dubai last year. One former Litasco trader says the group had taken over an entire floor in a high-rise tower at the heart of the free zone. Switzerland-headquartered Litasco declined to comment.

DMCC-registered Demex Trading and Qamah Logistics are also among the larger traders of Russian crude. Both were incorporated during the past three years; neither could be reached for comment.

Trading Russian oil from Dubai is not illegal. Western sanctions only prohibit imports into the EU, UK and other countries enforcing the G7’s rules, such as Switzerland. Under the restrictions western companies can also continue selling Russian oil to other parts of the world if that oil is sold under a certain price.

The measures have been designed to keep Russian oil flowing to new non-western buyers, while reducing the revenue flowing to the Kremlin. Washington has even encouraged traders to keep moving Russian oil to avoid supply disruptions, provided they trade below the relevant price cap.

While Dubai-registered traders are not obliged to comply with the price cap, some have chosen to do so in order to maintain access to western services such as shipping, banking and insurance.

Geneva-based Gunvor, for example, has said it incorporated a second entity in Dubai in October to segregate “the handling and financing of any potential Russia-related deals” from the rest of its trading activities.

Gunvor had ceased trading Russian crude but bought about $330 million of Russian refined fuels between January and April, all in compliance with the west’s sanctions and price cap policy, it told the FT in June. It disputed some of the customs data, which showed exports by Gunvor worth over $500 million during the period.

Helima Croft, a former CIA analyst and global head of commodities research at RBC Capital Markets, says Washington does not mind where Russian oil is traded from provided it is done transparently. “As long as these Russian barrels are below the cap, these trading houses are doing nothing wrong,” she says. “It’s Washington’s price cap plan in action.”

Other traders, however, appear to be using Dubai-based subsidiaries to buy and sell oil above the cap by employing non-European shipping and financial service providers.

Paramount Energy and Commodities, for example, transferred its Russian trading activity last year from Geneva to a DMCC-registered subsidiary, which has continued to market a crude blend from eastern Russia that has consistently traded above the G7’s $60-a-barrel cap, according to pricing data. Swiss authorities questioned the trader in April about its switch to Dubai, the FT reported in July.

Paramount said at the time that it had responded to the questions in full, informing the regulator that the Swiss entity had ceased all transactions involving Russian oil before the price cap took effect and that its UAE affiliate was a separate legal entity with different directors.

Rosneft’s traders?

The biggest contributors to Dubai’s Russian oil boom, however, are not established players but a network of previously unknown companies with opaque ownership structures that are collectively moving billions of dollars of oil a month.

Among the largest traders of both crude oil and refined fuels from Russia is a company called Tejarinaft FZCO, registered in another free zone called Dubai Silicon Oasis.

Tejarinaft – “oil trade” in Arabic – was incorporated two months after the Russian invasion. Corporate records list Hicham Fizazi, a Moroccan national, as the sole director and the general manager. He is the only named shareholder, although the records do not disclose whether he owns all or part of the company.

Corporate records reviewed by the FT also list Fizazi as the sole director and only named shareholder of at least two other UAE-registered companies trading Russian oil: Amur Trading FZCO, registered in Dubai Silicon Oasis in August, and Amur Investments Ltd, registered in Abu Dhabi in September.

Rival traders say they had never heard of Fizazi before last year. They believe the three companies are part of a network set up by, or on behalf of, Rosneft to help the Kremlin-controlled producer to move its oil after European former partners such as Trafigura and Vitol stepped away from trading Russian crude last year.

Customs declarations suggest that Tejarinaft, Amur Trading and Amur Investments have only ever exported oil from Rosneft or Rosneft projects, trading almost $8 billion of Russian crude and refined fuels from the producer between September and April.

Tejarinaft alone exported $6.71 billion of Russian oil between September and March, exclusively for Rosneft, according to the 394 customs declarations during the period.

Rosneft did not respond to a request for comment. Emails to the address provided on Tejarinaft’s website bounced back as undeliverable, the telephone number listed there connected to a general inquiries line for the free zone while the online “contact us” form did not work. Amur Trading and Amur Investments could not be reached.

Ben Higgins, a Dubai-based investigations specialist at risk consultancy Wallbrook, part of Anthesis, says he has seen a big increase in requests from banks and other corporate clients for further diligence on Dubai-registered trading companies over the past year.

“Incorporated across various Dubai free zones, the target entities are often very low profile and their owners – on paper – aren’t Russian nationals,” he says. “Deeper research and analysis, however, often find multiple leads back to Russia.”

Some of the individuals Wallbrook has investigated also appear to have played similar roles in businesses dealing with oil from Iran or Venezuela, Higgins says, “always a hop ahead of the authorities, shuffling between hotspots such as Cyprus, Hong Kong, Latvia and Dubai”.

‘Faith in the system’

While the Russian oil trading business is scattered across Dubai’s sparkling high-rise offices, the heart of the physical trade is 100 kilometres east at the dusty port city of Fujairah.

The Fujairah Oil Industry Zone (FOIZ) is the largest commercial storage facility in the region for refined oil products. The site’s 262 towering white storage tanks stretch for several kilometres along either side of the road from the port. Right now many of them are filled to the brim with oil, much of it from Russia.

Monthly imports of Russian fuels into Fujairah increased from nothing in April 2022 to a peak of 141,000 barrels a day during December. According to Pamela Munger, an oil analyst at data provider Vortexa, that represented 40% of all fuel flowing into the terminal that month. Last month, Fujairah received an average of 105,000 barrels a day from Russia, the data shows.

The influx has driven up the prices operators can charge for storage but also created a “two tier market, where those tanks willing to take Russian product can charge a premium,” one Dubai-based oil trader said. FOIZ did not respond to a request for comment.

VTTI, which is partly owned by Vitol, is one of a handful of western companies operating storage tanks at Fujairah. VTTI said it did accept Russian fuels into its tanks and stressed that “there are no sanctions in UAE with regards to Russian products, nor are western sanctions applicable to the UAE”.

“Hence, product owners are allowed to move and trade Russian products into and through UAE […] and storage companies are allowed to store Russian product in the UAE,” it said. Even if a cargo was required to comply with the G7’s price cap – for example, because it had been bought or sold by a western company or had used western shipping or insurance services – those restrictions did not apply to the storage provider, it added.

A further sign of the boom in activity at Fujairah was the purchase in May by Dubai-based newcomer Montfort of an oil refinery in the FOIZ previously owned by German utility Uniper. Montfort, set up by former Trafigura trader Rashad Kussad in 2021, outbid several companies including Vitol, which owns a neighbouring facility, according to three people familiar with the deal.

Russian situation was just the start

Montfort declined to comment further on the deal, adding that its commodity trading activities at Fujairah, and elsewhere in the world, comply with “all applicable laws, regulations, and sanctions, including those of the EU, Switzerland, UK and US”.

Such investments in physical infrastructure may have been precipitated by the war in Ukraine, but they also reflect a growing belief in the UAE that even if the Russian-fuelled boom eventually wanes, the global oil trading landscape has been changed forever.

“People put the cause as the Russian situation, but that was just the start of it,” says one UAE-based trading executive, who now expects European commodity bankers to follow the traders to Dubai as Emirati banks seek to expand their service offering for the sector.

For Russian oil, as for many Russian nationals, Dubai has proved to be a welcoming, but potentially temporary, home while the war in Ukraine continues. For the scores of expatriate oil traders manning trading desks across the city, the move looks more permanent.

“It is no longer a transitory environment, where you say: ‘I’ll try my luck and if I lose money I’ll hand back the keys and fly back to Europe’,” says Kpler’s Stanley. “People are now setting up roots here. People have got faith in the system.”

swissinfo.ch by Tom Wilson, August 4, 2023

Kremlin looks to raise sector’s taxes again as international sanctions take toll.

Russian authorities are continuing to step up efforts to reverse the ongoing decline in revenues from the country’s oil and gas sector, which have been falling steadily since March.

The oil and gas sector has been a major contributor to Russia’s budget, but revenues have failed to keep pace with government spending that has increased greatly since the invasion of Ukraine early last year and pushed the budget deficit to 2.6 trillion roubles ($28.9 billion) between January and June this year, according to the country’s Finance Ministry.

New tax increases were imposed in March in an effort to boost revenues, but the ministry has admitted that oil and gas producers paid less in direct taxes in April, after the changes were introduced, than the previous month — 647 billion rubles in April against 688 billion rubles in March.

In a new effort to help combat the decline, the Finance Ministry said the country’s oil export tax, paid by producers as soon as they export volumes outside Russia, will increase by more than 8% to $2.30 per barrel from 1 August this year.

And Russia’s lower house of the parliament, the Duma, has rubber-stamped a government proposal to increase the minimum discount for the country’s most commonly traded oil blend, Urals, against North Sea benchmark Brent.

This measure aims to increase the revenues paid from the oil production tax, which companies have to pay once their oil is extracted from the ground and will need to be approved by the parliament’s upper chamber and signed by President Vladimir Putin before coming into force.

Both measures have come after the Kremlin reportedly instructed state pipeline operator Transneft to reduce the transportation of Urals blend crude to the country’s ports in the north, northwest and south in order to fulfil a promise to the Opec+ group to cut Russia’s oil exports by 500,000 barrels per day.

The Russian Energy Ministry said in a statement that it ordered Transneft to reduce previously agreed pipeline export allocations for country’s producers by 15.4 million barrels in the third quarter of this year.

Urals shipments to fall

Moscow business daily Kommersant suggested that most of the export cuts will be implemented by reducing seaborne shipments of Urals crude, while continuing to send supplies as planned of its ESPO Blend — better quality light oil — from West Siberia to China and Asia-Pacific via the East Siberia–Pacific Ocean trunkline and terminal at Kozmino in the country’s far east.

Also excluded from the Russian oil export cut are development projects in the country’s Arctic, where producers Gazprom Neft and Lukoil operate their own marine export terminals and do not deliver crude into the country’s trunkline network.

ESPO and other Russian proprietary oil blends have been sold this week above the price cap on Russian oil that G7 country set at $60 per barrel in December.

However, pricing agency Argus has reported that Urals continued to be sold below the established price cap limit last week, despite the Kremlin banning Russian producers from agreeing to comply with the G7 price cap mechanism.

The Russian Finance Ministry said that in June, the country’s oil and gas producers paid 529 billion roubles in direct taxes on their production against 571 billion roubles in May.

The year’s highest revenue of 688 billion rubles was recorded in March.

Some industry analysts in Moscow suggested that while the announced oil export reduction may narrow the spread between Urals and Brent — one of the government’s aims — a lower discount may be insufficient to generate the desired growth in oil revenues.

Upstream by Vladimir Afanasiev, August 4, 2023